Method and materials for manipulating hydraulic fracture geometry

ABSTRACT

A method for manipulating hydraulic fracture geometry. In one embodiment, the method comprises injecting a fracturing fluid into a well to generate one or more hydraulic fractures in a subsurface rock formation and then substantially draining any fluids from the one or more hydraulic fractures. The method may further comprise injecting a hydrophilic polymer and one or more crosslinking agents into the well to subsequently form low-density hydrogels which may then screen out only each tip of the one or more hydraulic fractures. A working fluid may then be injected into the well to increase fracture width of the one or more hydraulic fractures without substantially increasing fracture length. In an alternative embodiment, the hydrophilic polymer may be fully crosslinked by the one or more crosslinking agents and injected as pre-formed particle gels (PPGs) which may also screen out only each tip of the one or more hydraulic fractures.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.17/145,666 filed on Jan. 11, 2021, issued as U.S. Pat. No. 11.326,435 onMay 10, 2022, the disclosure of which is incorporated by referenceherein in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND OF THE INVENTION Field of the Invention

The present invention relates to a method for manipulating hydraulicfracture geometry in a rock matrix. More particularly, the presentinvention relates to a method for manipulating hydraulic fracturegeometry in a rock matrix so as to optimize energy storage and powergeneration in a geomechanical pumped storage system, or alternativelyimprove mineral resource production.

Background of the Invention

In the oil and gas industry, the presence of hydraulic fractures invarious rock formation matrices surrounding a well may be commonlyencountered. For instance, hydraulic fractures may be deliberatelygenerated in the course of producing unconventional hydrocarbonresources, or even accidentally created during drilling operations. Ineither case, some control over the fracture geometry of these hydraulicfractures may be desirable.

Currently, the extent to which an operator controls or manipulateshydraulic fracture geometry may be in the form of eliminating furtherpropagation of a hydraulic fracture. In the case of a deliberatelygenerated hydraulic fracture, propagation may be arrested when aproppant slurry becomes dehydrated during the fracturing process as aresult of rock matrix leak-off. The resulting “tip screen-out” mayincrease fracture width near the well. This is usually unintentional,but may be exploited deliberately if the rock matrix permeability isknown in advance. In the case of an accidentally created hydraulicfracture, further propagation may be eliminated by simply plugging thehydraulic fracture completely during the drilling process. Plugging maybe achieved by filling the hydraulic fracture with lost circulationmaterials (LCMs) which may be included in the drilling fluid as aprophylactic or provided as a bolus or “pill” upon detection of thefracture. This manipulation of fracture geometry may be imperative so asto avoid a reduction in drilling efficiency, an increase in drillingexpenses, or complete loss of the well.

Various methods and materials have been developed in the oil and gasfield to effectively control or manipulate hydraulic fracture geometry,as it is a ubiquitous and long-standing issue. Most methods, as with thetwo cases above, involve filling all or most of the volume of thehydraulic fracture with more or less solid material to bridge thefracture, thereby stopping fluid flow and arresting further propagationof the fracture. Such methods are not suitable for selectively fillingthe tip of the fracture and leaving the bulk of the fracture open anduseful for other purposes such as, without limitation, storing energyand generating power in a geomechanical pumped storage system orimproving mineral resource production.

Consequently, there is a need in the art for a method for manipulatinghydraulic fracture geometry in a rock matrix (e.g., selectively pluggingor screening out hydraulic fracture tips) so as to optimize energystorage and power generation in a geomechanical pumped storage system,or alternatively improve mineral resource production.

BRIEF SUMMARY OF SOME OF THE PREFERRED EMBODIMENTS

These and other needs in the art are addressed in one embodiment by amethod for manipulating hydraulic fracture geometry comprising:injecting a fracturing fluid into a well to generate one or morehydraulic fractures in a subsurface rock formation, wherein thesubsurface rock formation surrounds the well; substantially draining anyfluids from the one or more hydraulic fractures; injecting a hydrophilicpolymer and one or more crosslinking agents into the well tosubsequently form low-density hydrogels, wherein the low-densityhydrogels screen out only each tip of the one or more hydraulicfractures; and injecting a working fluid into the well to increasefracture width of the one or more hydraulic fractures withoutsubstantially increasing fracture length.

These and other needs in the art are addressed in one embodiment by amethod for manipulating hydraulic fracture geometry comprising:injecting a fracturing fluid into a well to generate one or morehydraulic fractures in a subsurface rock formation, wherein thesubsurface rock formation surrounds the well; substantially draining anyfluids from the one or more hydraulic fractures; injecting pre-formedparticle gels (PPGs) into the well to screen out only each tip of theone or more hydraulic fractures, wherein the PPGs are particles of ahydrophilic polymer crosslinked by one or more crosslinking agents; andinjecting a working fluid into the well to increase fracture width ofthe one or more hydraulic fractures without substantially increasingfracture length.

These and other needs in the art are addressed in one embodiment by amethod for manipulating geometry of a hydraulic fracture, wherein thehydraulic fracture is disposed in a subsurface rock formationsurrounding a well, comprising: substantially draining any fluids fromthe hydraulic fracture; injecting a tip screen-out (TSO) mixture intothe well to screen out only the tip of the hydraulic fracture; andinjecting a working fluid into the well to increase fracture width ofthe hydraulic fracture without substantially increasing fracture length.

The foregoing has outlined rather broadly the features and technicaladvantages of the present invention in order that the detaileddescription of the invention that follows may be better understood.Additional features and advantages of the invention will be describedhereinafter that form the subject of the claims of the invention. Itshould be appreciated by those skilled in the art that the conceptionand the specific embodiments disclosed may be readily utilized as abasis for modifying or designing other embodiments for carrying out thesame purposes of the present invention. It should also be realized bythose skilled in the art that such equivalent embodiments do not departfrom the spirit and scope of the invention as set forth in the appendedclaims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of theinvention, reference will now be made to the accompanying drawings inwhich:

FIG. 1 illustrates a system for generating hydraulic fractures that maybe utilized by a geomechanical pumped storage system in accordance withone embodiment of the present invention; and

FIG. 2 illustrates a pressure response graph of a geomechanical pumpedstorage system in accordance with one embodiment of the presentinvention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Oil and gas wells may be capable of geomechanically storing energy andgenerating power. This may be achieved by using the energy obtained froman outside source to pump a fluid down a well comprising hydraulicfractures at substantially high pressures. Injecting the fluid mayresult in elastic deformation of a rock matrix surrounding the hydraulicfractures, thereby storing the energy used to deform the rock matrix aspotential energy. The stored potential energy may then be recovered uponejection of the fluid from the well, which may occur by allowing therock matrix to relax to its original position. By this process, oil andgas wells may function as geomechanical pumped storage systems, orgeomechanical batteries.

The performance of a geomechanical pumped storage system may besubstantially dependent on the hydraulic fractures utilized by thesystem, and more particularly the geometry of the hydraulic fracturesutilized by the system. For instance, the geometry of the hydraulicfractures may influence, without limitation, flow rate, reservoirpressure, and fluid storage capacity of the system, and thereby dictatethe amount of power that may be generated and the amount of energy thatmay be stored. As such, an operator may need to manipulate hydraulicfracture geometry for a geomechanical pumped storage system to optimizesystem performance. In embodiments, optimal system performance may beachieved by providing substantially long, wide, and horizontal hydraulicfractures. This hydraulic fracture geometry may be capable of deliveringsubstantial flow rates, reservoir pressures, and fluid storage capacity.

In embodiments, the hydraulic fractures present in the system may begenerated or pre-existing for the purpose of being utilized for energystorage, or rather for stimulating oil and hydrocarbon production in thewell. The hydraulic fractures, whether generated or pre-existing, may bepresent in rock matrices of ranging permeability (e.g., low permeabilityto high permeability). In any situation, the operator may be capable ofmanipulating the hydraulic fracture geometry.

FIG. 1 illustrates a hydraulic fracturing system disposed at a well sitesuitable for generating hydraulic fractures that may be utilized by ageomechanical pumped storage system. The hydraulic fracturing system maycomprise a sand truck 42, a storage tank 45, a blender truck 43, andhigh-pressure pumps 44. In embodiments, sand truck 42 may be any trucksuitable for providing sand or other materials such as, withoutlimitation, polymers, pre-formed particle gels (PPGs), viscosifyingagents, clays, or combinations thereof, at the well site. Storage tank45 may be any tank suitable for mixing and/or storing fracturing fluidsuch as, without limitation, water. In order to generate hydraulicfractures that may be utilized by a geomechanical pumped storage system,the fracturing fluid disposed in storage tank 45 may be drawn to blendertruck 43 to be mixed with the sand or other materials provided by sandtruck 42. This mixture may then be injected into a well 41, which may beany suitable oil and gas well drilled into a subsurface rock formation,using high-pressure pumps 44. In embodiments, the mixture may beinjected at any pressure sufficient for forming one or more hydraulicfractures 46 around well 41. The volume injected may be selected to be asubstantial fraction of the total working volume of the geomechanicalpumped storage system. In an optional embodiment, after the formation ofone or more hydraulic fractures 46, proppant particles 47 may be pumpedinto one or more hydraulic fractures 46 to maintain fracture formation.Further after formation, one or more hydraulic fractures 46 may bedrained of any fluids. In embodiments, the requisite pressure to formone or more hydraulic fractures 46 in the subsurface rock formation maygenerally have a linear dependency on well depth. Further, the requisitepressure may be any pressure above the fracture gradient. In someembodiments, a typical fracture gradient may be about 0.8 psi per footof well depth. Therefore, by way of example, a 3,000 foot well mayrequire a pressure of about 2,400 psi at the rock face to generate ahydraulic fracture. In addition to requisite pressure, well depth mayinfluence the orientation of one or more hydraulic fractures 46. Forexample, hydraulic fractures generated in shallow wells (i.e., wells upto 1,000 to 2,000 feet deep) may be horizontally oriented, whilehydraulic fractures generated in wells at greater depths may bevertically oriented.

Using the hydraulic fracturing system, an operator may generate one ormore hydraulic fractures 46 to generally be horizontally oriented andsymmetrically disposed within the subsurface rock formation about well41 with fracture lengths comparable to or larger than their depth belowthe surface of well 41. While hydraulic fractures with differentorientations, positionings, or lengths may be used, performance of thegeomechanical pumped storage system may be adversely affected. Further,the subsurface rock formation may be substantially impermeable orselected to be substantially impermeable so as to minimize leakage andallow for maximum fracture length. In embodiments, one or more hydraulicfractures 46 may be disposed in dense laminated shales. While other rockfabrics may be used, performance of the geomechanical pumped storagesystem may be adversely affected.

After generating and/or draining one or more hydraulic fractures 46 asdesired, an operator may increase the fracture width of one or morehydraulic fractures 46. For a given depth and fracture length, theability to increase fracture width may generally be dependent upon therock's fracture toughness (i.e., the fracture's ability to inhibitfurther propagation at its tip). As such, the operator may need toincrease the apparent fracture toughness of the subsurface rockformation by selectively plugging or screening out the tip or tips ofone or more hydraulic fracture 46 in order to increase the fracturewidth. Through the exploitation and extension of one or more hydraulicfractures 46, LCMs and conformance control materials and methods mayarrest the growth of one or more hydraulic fractures 46 and subsequentlyinflate one or more hydraulic fractures 46 to widths beyond thoseachievable with native fracture toughness. To increase the apparentfracture toughness of the subsurface rock formation, a tip screen-out(TSO) mixture may be injected into well 41 to fill, coat, or line one ormore hydraulic fractures 46. In particular, the TSO mixture may plug orscreen-out the tip of each one or more hydraulic fractures 46.

In some embodiments, the TSO mixture may comprise a synthetic orbiologically-derived hydrophilic polymer and one or more crosslinkingagents. When mixed, the hydrophilic polymer and the one or morecrosslinking agents may be capable of forming low-density hydrogels. Inembodiments, the concentrations of the hydrophilic polymer and the oneor more crosslinking agents may be selected to ensure low viscosity andlow density to ease injection and prevent settling. Further, theconcentrations may be selected to achieve viscous or rigid gels uponcompletion of injection. In embodiments, the hydrophilic polymer may bebased on an anionic, partially hydrolyzed, polyacrylamide at aconcentration, including the one or more crosslinking agents, from about0.01 wt. % to about 10 wt. % in water. Alternatively, the concentrationof the hydrophilic polymer, including the one or more crosslinkingagents, may be from about 0.1 wt. % to about 1 wt. % in water, orfurther alternatively about 0.5 wt. % in water. The one or morecrosslinking agents may be selected from a group including, but notlimited to, compounds comprising polyvalent metal cations, such as,without limitation, aluminum sulfate, chromium dichloride, chromiumtrichloride, and organic polyamines. In embodiments, the organicpolyamines may be, without limitation, polyethylene imine or amineterminated polymers of ethylene oxide. Further, the concentration of theorganic polyamines may be from about 0.001 wt. % to about 10 wt. % inwater. Alternatively, the concentration of the organic polyamines may befrom about 0.01 wt. % to about 1 wt. % in water, or furtheralternatively about 0.5 wt. % in water. In embodiments, the polyvalentmetal cations may also include, without limitation, Calcium(II),Chromium(II), Chromium(III), Aluminum(III), Iron(III), Titanium(IV),Zirconium(IV), or any combinations thereof. One skilled in the art mayrecognize any number of functionally equivalent combinations ofmaterials, including even cationic polymers and anionic crosslinkingagents, as well as neutral polymers and neutral organic crosslinkingagents. In embodiments, the one or more crosslinking agents may be aChromium(III) complex with a carboxylic acid or acids including, withoutlimitation, acetic acid, which may generate a range of gels (e.g.,viscous to rigid) over a range of time periods (e.g., hours to weeks)depending on the hydrophilic polymer concentration and temperature.

In order to plug or screen-out the tip of each one or more hydraulicfractures 46, the TSO mixture comprising the hydrophilic polymer and theone or more crosslinking agents may be injected into well 41 by anysuitable method. In some embodiments, the hydrophilic polymer and theone or more crosslinking agents may be mixed at the surface of well 41just before injection. In such an embodiment, the one or morecrosslinking agents may be timely inhibited from crosslinking thehydrophilic polymer so as to not form the low-density hydrogels untilproperly placed in one or more hydraulic fractures 46. In anotherembodiment, the hydrophilic polymer and the one or more crosslinkingagents may be injected separately into well 41. In such embodiments, thehydrophilic polymer and the one or more crosslinking agents may be mixedin-situ, thereby forming the low-density hydrogels in-situ. In someembodiments involving separate injection, the one or more crosslinkingagents may be injected into well 41 prior to the hydrophilic polymer. Inthis embodiment, the one or more crosslinking agents may be selectedbased on ability to adhere to the rock surface of hydraulic fractures,and therefore may promote adhesion via metal ions of the subsequentlyformed low-density hydrogels to the rock surface of one or morehydraulic fractures 46. The low-density hydrogels, however formed, maybe transported along one or more hydraulic fractures 46 to bridge,dewater, and/or form a packed bed of hydrogel material at each tip. As aresult, apparent fracture toughness may be increased and fluid flow tothe tip or tips of one or more hydraulic fractures 46 may besubstantially stopped, thus arresting further fracture growth.

In some embodiments, to aid in arresting further fracture growth, anoperator may optionally augment the low-density hydrogels using amixture of traditional LCMs. Augmenting the low-density hydrogels mayaid in achieving a desired sized to approximately match or slightlyexceed the fracture width of one or more hydraulic fractures 46, thusachieving bridging and/or forming of a packed bed at each tip. Inembodiments, the traditional LCMs may include, without limitation,bentonite clay, mineral fibers, silica flour, or any combinationsthereof.

In other embodiments, the hydrophilic polymer may be fully crosslinkedby the one or more crosslinking agents and in the form of PPGs prior toinjection into well 41. In such embodiments, the PPGs may be desiccatedand crushed to selected sizes and injected into well 41. Further, thePPGs may be swollen with water prior to injection into well 41 or afterinjection into well 41. In embodiments, the PPGs are pre-swollen priorto injection into well 41. Similarly to the low-density hydrogels, thePPGs may be transported along one or more hydraulic fracture 46 tobridge, dewater, and/or form a packed bed of hydrogel material at eachtip. Once again, this may increase the apparent fracture toughness andsubstantially stop fluid flow to the tip or tips of one or morehydraulic fractures 46, thus arresting further fracture growth. Inembodiments, the PPGs may be injected at a range from about 0.1 wt. % toabout 2 wt. % in water. To enhance performance and space-fillingabilities, the PPGs injected may be a mixture of a distribution ofcomplementary particle sizes. In embodiments, the distribution ofparticle sizes of the PPGs may range from about 10 microns to about 1centimeter. In alternative embodiments, the particle sizes of the PPGsmay be greater than 1 centimeter. Further, to enhance performance andspace-filling abilities, the PPGs may be injected into well 41 alongwith clays or other materials. In embodiments, the clays or othermaterial may be, without limitation, bentonite clay, mineral fibers,silica flour, or any combinations thereof. The clays or other materialsmay be added in the amount from about 1 pound per barrel of water up toabout 30 pounds per barrel of water.

Following the bridging of one or more hydraulic fractures 46 vialow-density hydrogels or PPGs, apparent fracture toughness maysubstantially increase and further fracture growth may be substantiallyarrested. As such, the geomechanical pumped storage system may operateat optimal performance. For instance, an operator may inject a workingfluid into the system, and due to the disabling of fracture growth theworking fluid may inflate one or more hydraulic fractures 46 and resultin maximum fluid storage capacity. Enabled by the low-density hydrogelsor the PPGs, the injected working fluid may serve to increase thefracture width of one or more hydraulic fractures 46, without extendingthe fracture length. Further, the system may deliver substantially highreservoir pressures and substantially high flow rates. Thus, hydraulicperformance of one or more hydraulic fractures 46 may be improved andthe fracture width may be greater than that achievable with only thenative fracture toughness of the subsurface rock formation. Inembodiments, the injected working fluid may be any suitable fluid suchas, without limitation, water, salt water, or the like. In someembodiments, modifiers may be added to the working fluid to promoteadhesion of PPGs to each other. The modifiers may include, withoutlimitation, cationic polymers like PEI (polyethyleneimine),polydiallyldimethylammonium chloride (polyDADMAC), cationicpolyacrylates, chitosan, or any combinations thereof.

To further illustrate various illustrative embodiments of the presentinvention, the following examples are provided.

Example 1

In a demonstration of an embodiment of the present method, a horizontalfracture at a depth of 1210 feet was first created using 50 bbl. ofwater viscosified with guar gum. The fracture was monitored during ashut in for 24 hours and then depressurized. The fracture was theninflated with 100 bbl. of water loaded with a mixture of pre-swollen 1-2mm and sub-mm pre-formed polyacrylamide PPG particles. The PPG mixturewas augmented with bentonite and mineral fiber. The injection pressurewas observed to increase during injection, as opposed to a decreasingprofile as expected for a short horizontal hydraulic fracture. Thefracture was observed during shut in, then a series of similarinjections of 250 bbl. each were performed up to a total of 1000 bbl.After each stage the pressure was monitored and then flowback testedthrough a fixed choke. At each stage, the injection and shut-inpressures increased while the flow back volumes increased roughly inproportion to the net pressure in the fracture. The net pressure in thefracture during shut-in after 1000 bbl. was observed to be over twotimes greater than the overburden pressure expected at a depth of 1210feet. These results are consistent with an increase of fracture width ata constant fracture length.

Example 2—Engineered Tip-Screen Out

A horizontal fracture formed at 1210 feet was evaluated for potentiallyengineering tip-screen out in pre-formed fractures using a mixture oflost circulation and conformance control materials. This class ofmaterials is used in the oil field to plug thief zones encounteredduring drilling or during water flood operations, and comprise particlesand fibers ranging in size from microns to centimeters. Typicalmaterials include bentonite clay, crushed walnut shells, mineral fibers,and the swellable PPGs, among many others. A candidate mixture wassupplied while inflating the horizontal fracture in stages up to 1000bbl. of fluid. The pressure response, shown in FIG. 2 , is indicative ofa horizontal fracture with expanding width at a nominally constantlength. A freely inflating horizontal fracture typically displays amonotonically decreasing net pressure as the fracture extends,asymptotically approaching the overburden pressure. Instead, this systemdisplays increasing pressure with volume. In the small radius regime,the fracture width (and volume) is proportional to net pressure (Hooke'slaw spring behavior). Further, the pinch times for the three stagestested increased monotonically with volume: 52, 72 and 101 seconds,respectively. This result demonstrates an effective means for arrestingfracture growth and increasing the effective fracture toughness of therock matrix. Also, it is noted that in this system the overburdenpressure expected is about 700 psi; the effective net pressure achievedwas easily two times above overburden pressure.

In addition to optimizing energy storage and power generation in ageomechanical pumped storage system, this method for manipulatinghydraulic fracture geometry may improve mineral resource production. Forinstance, following the bridging of one or more hydraulic fractures 46via low-density hydrogels or PPGs, with fracture toughness substantiallyincreased and further fracture growth substantially arrested, anoperator may inject a working fluid comprising any suitable proppant bedinto the system. Due to the disabling of fracture growth, the workingfluid comprising the proppant bed may prop and inflate one or morehydraulic fractures 46 to widths beyond those previously achievable andallow for high conductivity to improve mineral resource production.

Although the present invention and its advantages have been described indetail, it should be understood that various changes, substitutions andalterations may be made herein without departing from the spirit andscope of the invention as defined by the appended claims.

What is claimed is:
 1. A method for bridging one or more hydraulicfractures of a well, comprising: (A) injecting a tip screen-out mixtureinto the well, wherein the tip screen-out mixture comprises: ahydrophilic polymer of anionic polyacrylamide which is hydrolyzed atleast in part; and one or more crosslinking agents selected from a groupof compounds consisting of polyvalent metal cations, wherein theconcentration of the hydrophilic polymer and the one or morecrosslinking agents is between about 0.01 wt. % and about 10 wt. % inwater, (B) mixing the hydrophilic polymer and the one or morecrosslinking agents to form hydrogels in-situ; (C) bridging each tip ofthe one or more hydraulic fractures by transporting the hydrogels alongthe one or more hydraulic fractures as a result of the injecting;wherein the group of compounds consisting of polyvalent metal cationscomprises Calcium (II), Chromium (II), Chromium (III), Titanium (IV), aChromium (III) complex with one or more carboxylic acid, a Chromium(III) complex with acetic acid, or combinations thereof.
 2. The methodof claim 1, further comprising injecting lost circulation materials toaugment bridging of each tip with the hydrogels.
 3. The method of claim2, wherein the lost circulation materials comprise bentonite clay. 4.The method of claim 1, wherein concentrations of both the hydrophilicpolymer and the one or more crosslinking agents selected from the groupof compounds consisting of polyvalent metal cations are selected to formthe hydrogels as rigid hydrogel.
 5. The method of claim 1, wherein thepolyvalent metal cations are organic polyamines.
 6. The method of claim5, wherein the organic polyamines are amine terminated polymers ofethylene oxide.
 7. The method of claim 5, wherein concentration of theorganic polyamines is between about 0.01 wt. % and about 1 wt. % inwater.
 8. The method of claim 1, wherein the concentrations of both thehydrophilic polymer and the one or more crosslinking agents selectedfrom the group of compounds consisting of polyvalent metal cations areselected to form the hydrogels as viscous hydrogels.
 9. The method ofclaim 1, wherein the concentrations of both the hydrophilic polymer andthe one or more crosslinking agents selected from the group of compoundsconsisting of polyvalent metal cations are selected to form thehydrogels over a time period, wherein the time period is greater thanone hour and less than or equal to one week.
 10. The method of claim 1,wherein the concentrations of both the hydrophilic polymer and the oneor more crosslinking agents selected from the group of compoundsconsisting of polyvalent metal cations are selected to form thehydrogels over a time period, wherein the time period is greater thanone week.